Water Alternating Gas Injection Research Articles

WAG injection in porous media: A microfluidic analysis

Water Alternating Gas (WAG) injection is one of the common methods to displace oil in porous media, which is relevant to many applications including soil remediation or enhanced oil recovery from underground reservoirs. We conducted a comprehensive series of experiments to extend the fundamental understanding of WAG injection in porous media. Three types of porous media were manufactured with a 3D printer in this investigation. The first medium had single permeability (S), the second one was fractured (F), and the third one was a medium with dual permeability (D). The porous media were saturated with silicone oil. Nitrogen and water were used to displace oil under different WAG ratios of 4:1, 2:1, 1:1, 1:2, and 1:4. High-resolution imaging was used to quantify displacement dynamics. The highest oil recovery was observed under WAG ratio of 1:1, i.e., the equal slug size of the water and gas. The obtained results showed that the WAG ratio of 1:1 injection in the S medium recovered 55% of the oil, while in the F and D medium, the recovery efficiency was 36% and 47%, respectively. Our findings offer new insights regarding effects of heterogeneity on WAG injection efficiency in porous media under different boundary conditions.

Techno-economic life cycle assessment of CO2-EOR operations towards net negative emissions at farnsworth field unit

Optimizations of CO2 Water Alternating Gas(WAG)- systems with multi-objectives of incremental recovery and maximization of CO2 storage are challenging. The incorporation of a total Greenhouse gas (GHG) life cycle assessment is mostly ignored leading to inaccurate estimation of overall net carbon emissions of their operations. In this study, the effect of a total GHG life cycle assessment on a multi-objective CO2-WAG optimization with integrated techno-economic assessment (TEA) which factors carbon tax credit is conducted. A life cycle assessment (LCA) was conducted utilizing a 20 -year optimized post history matched data from a high fidelity reservoir simulation model. Using data generated from the optimum result, a techno-economic life cycle analysis was further conducted. The first scenario classified as the base model had an estimated 81% of purchased CO2 sequestered. The results through a comprehensive techno-economic LCA model yielded a net estimate of 73% of purchased CO2. The optimized forecasted model which considered key operational and reservoir factors such as WAG ratio, injection rates and periods, and well specification resulted in an improved sequestration of 92% of purchased CO2. However, this also dropped to 84% after taking it through LCA. These results clearly indicate a significant amount of net CO2 is not accounted for when operations are not analyzed through LCA. From the LCA, direct flaring volumes of CO2, energy consumption and efficiency of unit equipment were noticed to be the major causes of these reductions. Considering ten main sources of energy as source of energy generation, a comparative techno-eco LCA was conducted. The results confirmed a lower net volume and NPV for energy sources with higher carbon footprints and vice versa. Thus, a total LCA of CO2-WAG greatly influences net storage factor of purchased CO2 and hence project NPV where tax credit/incentives per ton of CO2 sequestered is considered. Although operational conditions are optimized for best results, there are significant factors that leads to minimization of net storage factor. This study therefore provides an insightful information for optimizing CO2-WAG multi-objectives to achieve minimum GHG emission.

A Comparison of The Performances of Conventional and Low Salinity Water Alternating Gas Injection for Displacement of Oil

This study focuses on identifying the crucial physical and chemical factors, such as gravity, initial oil phase, injection depth, vertical to horizontal permeability contrast, and salinity of injected water for improving oil recovery factor during water alternating gas (WAG) injection. The conventional WAG injection attracts interest from oil and gas industry and hence, has become one of the most reliable enhanced oil recoveries (EOR) techniques. During WAG injection, due to gravity effect, water subsides below oil layer while gas overflow above the oil layer. In fact, water sweeps bottom zones of the reservoir and gas sweep the attic oil at the upper zones of the reservoir. Although the conventional WAG does improve oil recovery factor, there still remains a substantial amount of oil in reservoir pores due to rock-fluid and fluid-fluid interfacial tensions (IFT) that leads to the capillary forces impeding the microscopic displacement efficiency. The low salinity waterflooding (LSWF) was therefore proposed to break the IFT between rock clay and fluids, and further increase oil recovery factor. Recent researches revealed that LSWF alters oil-wet reservoir to water-wet behavior. This wettability alteration is believed to be the main mechanism of LSWF to improve oil recovery. Other mechanisms of LSWF include multi-ion exchange (MIE) between rock clay minerals and injected salt water, pH increase, and fines migration. In this study, the CMG GEM simulator was used to simulate conventional WAG injection and LSWAG injection. The simulation results showed that there is an increase of oil recovery factor of about 6% for WAG injection with low salinity water of 1027ppm to sea water of 51,346 ppm. The simulations have also showed that the physical factors namely, gravity, initial oil phase, injection depth, vertical to horizontal permeability contrast are influential on the displacement efficiency and must be studied thoroughly in the design of LSWAG operations besides the salinity and chemical composition of the injection water.

A Mechanistic Study of Wettability Alterations in Sandstone by Low Salinity Water Injection (LSWI) and CO2 Low Salinity Water-Alternating-Gas (WAG) Injection

Low salinity water injection (LSWI), an emerging Enhanced Oil Recovery (EOR) method, has proven to be effective in increasing oil recovery by wettability alteration. As low salinity water is injected into the reservoir, the pre-established equilibrium is disturbed. The chemical reactions among the oil/brine/rock system alters the existing wettability, resulting in enhanced oil recovery. Water-alternating-gas (WAG) injection is also a leading EOR flooding process in light to medium oil sandstone and carbonate reservoirs. A recently proposed hybrid EOR method, CO2 low salinity (LS) WAG injection, shows promise based on experimental and simulation studies, compared to LSWI or CO2 injection alone. Wettability alteration is considered as the dominant mechanism for CO2 LSWAG injection. In this study, a new displacement contact angle measurement which better mimics the actual displacement process taking place in a reservoir is used, aiming to investigate the effect of monovalent and divalent cations, CO2, and injection schemes. It is found that the injection of NaCl low salinity water alters the wettability towards slightly water-wet, and the injection of CaCl2 low salinity water alters the wettability towards slightly oil-wet. The injection of CO2 promotes water-wetness and geochemical reactions between oil and brine. Injection scheme of CO2 and NaCl low salinity water is more efficient than WAG cycle of CO2/NaCl in wettability alteration towards more water-wet. However, the opposite trend is observed with CaCl2 low salinity water, of which WAG cycle of CO2/CaCl2 is more efficient in altering wettability towards water-wet. The oil drop deformation process during LSWI resembles the process of oil removal using surfactant. As CO2 is introduced, due to the acidic effect of CO2 and ion exchange, it acts to wet the rock surface, leading to a more water-wet state. With introduction of CO2, the oil drop deformation resembles the “roll-up” oil removal process.

Dissolution behaviour in carbonate reservoirs during WAG injection: A preliminary experimental study

In this study, a core flooding experiment using a water-alternating-gas (WAG) injection was conducted to evaluate its impact on the petrophysical properties of an initially oil-saturated heterogeneous carbonate core sample. Carbon dioxide (CO2) and synthetic formation brine were injected (0.5 pore volume CO2 alternating with 0.5 pore volume brine) alternately following establishment of waterflooding residual oil saturation under reservoir conditions. Gas porosity, gas permeability, NMR (nuclear magnetic resonance) T2 measurements, and X-ray CT scanning were conducted preand post-core flooding. The results show that CO2-WAG injection resulted in substantial additional oil recovery (~30 %) under the applied experimental conditions. The results also show an increase in the permeability of the tested sample from 1.5 to 16 mD, which could be attributed to mineral dissolution. X-ray CT imaging shows signs of excessive mineral dissolution and formation of wormhole structures. It is believed that dissolution within the tested core plug caused the WAG fluids to follow the newly wormhole (causing them to enlarge further), and consequently bypassing many parts of the sample. Therefore, despite a significant increase in oil recovery, a large amount of oil is still left behind.

Preparation for the introduction of SWAG at the fields of PJSC «Tatneft»

The results of laboratory studies of filtration processes on models of a terrigenous reservoir are presented in order to develop optimal compositions for simultaneous water and gas injection and foam assisted water alternating gas injection on the reservoir. The experiments were carried out on rock samples drilled from the core of terrigenous deposits of the Kynovsko-Pashiy horizon. The use of water-gas mixtures with foam-forming surfactants taking into account the field conditions of the fields of PJSC TATNEFT has been established will make it possible to obtain the greatest increase in oil recovery. Studies of the multiplicity and stability of foam systems have shown that non-ionic foaming surfactants TN-PO-1, TN-PO-2 and AF9-12 are best suited for use in FAWAG of the reservoir. The results of studies of the properties of foams depending on the concentration of surfactants are presented, recommendations are given on the use of specific reagents for the implementation of FAWAG, taking into account the conditions of specific fields. The use of SWAG and FAWAG technologies is not only increase oil recovery, but also significantly reduce the volume of irrationally used associated petroleum gas, which is one of the most important tasks for sustainable development goals. Keywords: enhanced oil recovery; filtration studies; simultaneous water and gas injection; foam assisted water alternating gas injection; foaming surfactants.

Importance of accounting macro heterogeneity of productive strata to improve efficiency of water alternating gas injection process

The paper focuses on improvement of reliability of geological information used in the water alternating gas injection projects for productive strata in the course of scavenger oilfield development. Spotlight is on the study of macro heterogeneities revealed by interpretation of drilling and seismic survey data. One of the critical objectives of this research is updating of interwell correlation according to the analysis of seismic wavefield recorded in the interval of productive strata occurrence. The paper describes a casestudy of the revised concept on the structure of BV10 stratum in the Nizhnevartovsk oil and gas area of the West Siberian oil and gas province. As a result, instead of the current concept on the parallel bedding of the test sedimentation, the progradation structure of the latter is assumed, which eliminates the use of wouldbe lithological screens in delineation of oil reservoirs. The disregard of the progradation structure in oilfield development would have an adverse influence on the oil recovery efficiency. The integrated interpretation of drilling and seismic survey data reveals screening fractures which make an impact on oil displacement efficiency. It is necessary to take such fractures into account in water alternating gas injection. Inclusion of sufficient vertical discriminability of well information and lateral discriminability of seismic survey data in the analysis allows predicting the change in petrophysical parameters in interwell space. The authors exemplify interpolation of well data with regard to wavefield properties. The information on macro heterogeneities of reservoir properties helps improve the water alternating gas injection performance and, accordingly, enhance the sweep efficiency. The paper presents also the physical framework for the adjustment of fluid flow in reservoirs using the seismic survey data. This paper has been supported by the RUDN University’s Strategic Academic Leadership Program.

Investigation of enhanced CO2 storage in deep saline aquifers by WAG and brine extraction in the Minnelusa sandstone, Wyoming

Geological CO2 sequestration in deep saline aquifers has been extendedly investigated to reach the goal of carbon neutral as large amount of CO2 can be reduced in a short time. This study investigates the feasibility of water-alternating-gas (WAG) injection and brine extraction on enhancing CO2 storage in a target deep saline aquifer, Minnelusa Sandstone in the Powder River Basin (PRB) of Wyoming. An integrated numerical model is developed to account for four scenarios: (1) CO2 continuous injection (CI) through one injection well, (2) WAG injection through one injection well, (3) CO2 CI through one injection well and brine extraction through one producer, (4) WAG injection through one injection well and brine extraction through one producer. Simulation results suggest that WAG injection and brine extraction corporately make it possible to enhance CO2 injectivity while securing CO2 storage safety. For instance, WAG injection considerably reduces structural trapping contribution while enhances dissolved and residual trapping contributions. As for brine extraction, it can decrease the maximum averaged reservoir pressure by 37% and 22% for CI and WAG injection, respectively. Besides, sensitive analyses of the operational parameters for the fourth scenarios are performed. Results reveal that, when the amount of total CO2 injection has been predetermined, CO2 injection time and rate within each period of WAG should be small whereas it is preferable to have large water injection time and rate. This is to secure desirable dissolved and residual trapping contributions (store CO2 with safety). Sensitive degree results confirm that CO2 injection rate, water injection time, and CO2 injection time of WAG injection exhibit significant effects on CO2 storage whereas the impacts of producer bottom-hole pressure (BHP), water injection rate, and CO2-water injection time are relatively weaker. This study not only sheds light on achieving double-win goal: enhance CO2 injectivity and store CO2 with safety, but also can be a critical reference for other CO2 storage in deep saline aquifers.

Literature Review of Hybrid CO2 Low Salinity Water-Alternating-Gas Injection and Investigation on Hysteresis Effect

Low salinity water injection (LSWI) is considered to be more cost-effective and has less environmental impacts over conventional chemical Enhanced Oil Recovery (EOR) methods. CO2 Water-Alternating-Gas (WAG) injection is also a leading EOR flooding process. The hybrid EOR method, CO2 low salinity (LS) WAG injection, which incorporates low salinity water into CO2 WAG injection, is potentially beneficial in terms of optimizing oil recovery and decreasing operational costs. Experimental and simulation studies reveal that CO2 LSWAG injection is influenced by CO2 solubility in brine, brine salinity and composition, rock composition, WAG parameters, and wettability. However, the mechanism for increased recovery using this hybrid method is still debatable and the conditions under which CO2 LSWAG injection is effective are still uncertain. Hence, a comprehensive review of the existing literature investigating LSWI and CO2 WAG injection, and laboratory and simulation studies of CO2 LSWAG injection is essential to understand current research progress, highlight knowledge gaps and identify future research directions. With the identified research gap, a core-scale simulation study on hysteresis effect in CO2 LSWAG injection is carried out. The results indicate different changing trend in oil recovery due to the impact of salinity on hysteresis and excluding of hysteresis effect in CO2 LSWAG injection simulation and optimization might lead to significant errors.

Water-Plus-Gas Injection on a Bakken Well Pad May Solve Problems That Stymied Shale EOR

_ After years of enhanced oil recovery (EOR) tests in the Bakken, one method finally appears to have added to a well’s ultimate production. The Liberty Resources well “is perhaps the first one that had clear, indisputable evidence of incremental oil. I do firmly believe we are on the right track for cracking the code for Bakken EOR,” said Jim Sorensen, director of subsurface R&D for the University of North Dakota Energy and Environmental Research Center (EERC) which provided technical support and funding. The gain predicted after the treatment with water alternating with gas injection (WAG) is not huge. A paper on the test, which was limited to a single 30-day injection cycle, estimated it added 7,000 bbl to the ultimate production, based on decline curve analysis (URTeC 3722974). An updated analysis from EERC is expected in early 2023. While there are endless arguments over the accuracy of decline curve analysis, Gordon Pospisil, development advisor for Liberty, said incremental oil estimates look solid: “The oil rate response to water alternating gas injection was clearly measurable at over 7,000 bbls over the baseline trend.” The bigger news may be an injection method that can overcome two barriers to EOR in the Bakken and elsewhere. One is finding a way to keep the injected gas around the wellbore, and the other is significantly lowering the cost, primarily by slashing the volume of gas required. “Overall, we were pleased with the project outcome to date as we were able to build pressure, contain the injection within the DSU (drilling spacing unit), and make incremental oil,” Pospisil said. For the test, Liberty used a novel, computer-controlled injection system from a startup company, EOR ETC. This system can rapidly switch from gas to water injection based on the control system the company developed. This reduces the surface injection pressure required to significantly increase the downhole pressure level and helps contain the gas in the target zone. “I have never seen anything like that. It performed as advertised,” Sorensen said. The estimated long-term gain looks small compared to the 800,000 bbl of oil prior to the test. But Brian Schwanitz, president of EOR ETC, said the income from those barrels covered what they billed for pumping the job, which was a discounted rate reflecting Liberty’s willingness to be the first operator to use the device. What it accomplished stands out compared to the futility of past Bakken tests where far more gas was injected with little impact on the downhole pressure because so much of it leaked off through the fractured formation. The Bakken Debacle For a decade, companies in the Bakken, often in partnership with the EERC, have searched for ways to get more oil out of the play where the ultimate recoveries are usually below 10% of the oil in place, which is in line with other unconventional oil plays. Gas-injection EOR tests in oil-producing shale plays have been hit or miss, with most of the results in the Bakken in the miss column. The problem has been that much of the gas escapes from the target zone, making it impossible in some cases to achieve the pressure levels needed for effective EOR and it increases the volume of gas needed to uneconomic levels for gas-only projects to achieve improved ultimate recoveries.

Field Application and Experimental Investigation of Interfacial Characteristics of Surfactant and CO2 Alternative Injection.

CO2 injection and water alternating gas (WAG) injection are crucial to improve the oil recovery method and have optimized development in numerous oil fields. Many issues, such as gas channeling, water clogging, and a shortage of gas injection capacity, are addressed in the studies. Considering these conflicts, we suggest in this work a unique method of surfactant alternating gas (SAG) injection. Additionally, axisymmetric drop shape analysis and other approaches are utilized to explore the interface properties of a variety of systems, including CO2/carbonated water/water/surfactant/oil systems. SAG injection combines the advantages of surfactant and WAG injection. Although CO2 molecules have an effect on surfactant aggregation at the oil–water interface in the SAG system, carbonated water has little effect on surfactant performance in lowering oil–water interface tension. Pilot studies reveal that a SAG ratio of 3:2 at 74 °C and 0.5 wt% concentration significantly improves oil recovery.

Assessment of chemo-mechanical impacts of CO2 sequestration on the caprock formation in Farnsworth oil field, Texas

This study evaluates the chemo-mechanical influence of injected CO2 on the Morrow B sandstone reservoir and the upper Morrow shale caprock utilizing data from the inverted 5-spot pattern centered on Well 13-10A within the Farnsworth unit (FWU). This study also seeks to evaluate the integrity of the caprock and the long-term CO2 storage capability of the FWU. The inverted 5-spot pattern was extracted from the field-scale model and tuned with the available field observed data before the modeling work. Two coupled numerical simulation models were utilized to continue the study. First, a coupled hydro-geochemical model was constructed to simulate the dissolution and precipitation of formation minerals by modeling three intra-aqueous and six mineral reactions. In addition, a coupled hydro-geomechanical model was constructed and employed to study the effects of stress changes on the caprock’s porosity, permeability, and ground displacement. The Mohr–Coulomb circle and failure envelope were used to determine caprock failure. In this work, the CO2-WAG injection is followed by the historical field-observed strategy. During the forecasting period, a Water Alternating Gas (WAG) injection ratio of 1:3 was utilized with a baseline bottom-hole pressure constraint of 5500 psi for 20 years. A post-injection period of 1000 years was simulated to monitor the CO2 plume and its effects on the CO2 storage reservoir and caprock integrity. The simulation results indicated that the impacts of the geochemical reactions on the porosity of the caprock were insignificant as it experienced a decrease of about 0.0003% at the end of the 1000-year post-injection monitoring. On the other hand, the maximum stress-induced porosity change was about a 1.4% increase, resulting in about 4% in permeability change. It was estimated that about 3.3% of the sequestered CO2 in the formation interacted with the caprock. Despite these petrophysical property alterations and CO2 interactions in the caprock, the caprock still maintained its elastic properties and was determined to be far from its failure.

Evaluation of Gas-Based EOR Methods in Gas-Invaded Zones of Fractured Carbonate Reservoir

More than half of all recoverable oil reserves are found in carbonate rocks. Most of these fields are highly fractured and develop different zonations during primary and secondary recovery stages; therefore, they require a different developmental approach than conventional reservoirs. Experimental results for water-alternating gas injection [WAG] and foam-assisted water-alternating gas [FAWAG] injection under secondary and tertiary recovery conditions were used to investigate these enhanced oil recovery [EOR] methods in gas-invaded reservoirs. The relative permeability curves of the cores and the fitting foam parameters were derived from these experiments through history matching. These findings were then used in a quarter five-spot, cross-sectional, and a sector model of a carbonate reservoir where a double five-spot setup was implemented. The fracture and matrix properties’ impact on the recovery was illustrated through the cross-sectional model. The gas mobility reduction effect of the FAWAG was more noticeable than that of WAG. The apparent viscosity of the gas was increased due to the foam presence, which caused a diversion of the gas from the fractures into the matrix blocks. This greatly enhanced the sweep efficiency and led to higher oil recovery. The gas front was much sharper, and gravity overrides by the gas were much less of a concern. The properties of the fracture network also had a significant effect on the recovery. Oil recovery was found to be most sensitive to fracture permeability. At the same time, sweep efficiency increased substantially, improving the recovery rate in the early injection stages, and differed slightly at the ultimate recovery. However, a lower fracture permeability facilitated gas entry into the matrix blocks. The results of the reservoir sector model were similar to the core and pilot. However, the WAG injection recovered more of the uppermost layers, whereas significant portions of the lowest layer were not effectively recovered. In contrast, FAWAG was more effective in the lowest layer of the reservoir. The FAWAG was a beneficial aid in the recovery of gas-invaded fractured reservoirs, increasing the oil recovery factor with respect to WAG.

An experimental study to measure oil recovery factor by chemical agents and carbon dioxide after waterflooding.

Development of tight formations would be one of the main priority for petroleum industries due to the enormous demand to the fossil fuels in various industries. In this paper, we provided a set of experiments on the generated foams by carbon dioxide (CO2) and nitrogen (N2), cyclic CO2 injection, water alternating gas injection (WAG), active carbonated water injection (coupling surfactant effects and carbonated water (CW)), and introducing the impact of active carbonated water alternating gas injection (combination of WAG and CW injection) after waterflooding. Carbon dioxide is more feasible than nitrogen, it can be mobilize more in the pore throats and provided higher oil recovery factor. Generated foam with CO2 has increased oil recovery factor about 32% while it’s about 28% for generated foam by N2. Moreover, according to the results of this study, the maximum oil recovery factor for active carbonated water alternating gas injection, active carbonated water injection, and water alternating gas injection measured 74%, 65%, and 48% respectively.

An analytical model for performance prediction of miscible flooding methods

The main target of this study is to develop fast and efficient analytical model that can predict reservoir performance under the implementation of miscible flooding processes. The developed model uses upgraded fractional flow theories and several areal sweep efficiency models. Unlike previous attempts in this topic, the developed model accounts for reservoir instability factors such as reservoir heterogeneity, viscous fingering behavior and gravity segregation. In addition, it accounts for different Enhanced Oil Recovery (EOR) injection strategies including continuous solvent injection and simultaneous Water Alternate Gas (WAG) injection in both secondary and tertiary miscible displacement modes. Moreover, the model has been extended to account for different injection patterns including line drive and 5-spot. The model was validated against two actual field applications: (1) the WAG injection pilot project of Slaughter field, and (2) the miscible flooding pilot project of Garber field. The results of the model deviate from the results of the field measurements with a range of 7.3 to 20.4%. This match demonstrated the ability and the strength of the developed model. The model utilizes a limited set of input data that is available in the field at the early stages of the reservoir life. Therefore, it can be used as a pre-simulation tool to support the decision-making during the critical technology selection phase.

Optimization of Sensitive Technical Parameters of Water Alternating Gas Injection Displacement Based on Multi-indicator Orthogonal Design

In view of a series of comprehensive problems such as the limited space of conventional water displacement, the low-pressure maintenance level, and the greater contradiction during the high water cut period of 64-20 sub-block, the development potential of its conversion medium with carbon dioxide was evaluated. After determining that water alternating gas injection displacement was the dominant development method in the target area, the sensitive parameters were optimized based on multi-indicator orthogonal design, numerical simulation and comprehensive scoring. The research results show that the use of water alternating gas injection displacement in the high water cut period could better maintain the formation pressure and greatly increase the recovery percent. It has a large application potential in the target area and the final optimal parameters are as follows: gas injection time is 20 years, cycle is 8 months, velocity is 1 × 104 m3/d, gas-water ratio is 1 : 1 and bottom hole flowing pressure is 13 MPa. And the technical parameters of velocity and cycle have the most important contribution to the displacement effect during the high water cut period in the earlier period.

Mechanism study of enhanced oil recovery by entrapped gas in extra high water-cut reservoir

Water control is an effective method to enhance the oil recovery in the high water-cut reservoir. It is proved that the water production can be reduced by the entrapped gas in the oil field. But the mechanism is not well studied. In this paper, the mechanism of enhanced oil recovery by entrapped gas is studied by experiments and numerical simulation. Based on the core flooding tests and simulation study, the increments of oil recovery caused by entrapped gas are 8% and 2%, respectively. After the gas is entrapped in the core sample, the water relative permeability is decreased by 10.5% and the oil relative permeability is only decreased by 3.5%, which proved that the entrapped gas has a dramatic effect on blocking water phase. The more gas is entrapped, the more oil is produced. Different methods to achieve entrapped gas are also discussed, simultaneous water, and gas injection is a preferred entrapped gas formation method than gas injection method and water alternating gas injection method. Under the immiscible condition, the entrapped methane has a better performance on enhancing oil recovery than the entrapped nitrogen.

Computational fluid dynamic simulation of multi-phase flow in fractured porous media during water-alternating-gas injection process

Naturally fractured reservoirs (NFRs) are among major oil and gas producing reservoirs that are commonly targeted for various enhanced oil recovery (EOR) techniques, particularly water-alternating-gas (WAG) injection. Production from NFRs is complicated due to the flow communication between the matrix and fractures in such porous media. The implementation of WAG injection in NFRs features inherent complexities not only related to the three-phase flow, saturation history, and cycle-dependent hysteresis of the individual phases, but also the fracture-matrix communication, fingering, and early breakthrough of the injected phases particularly during gas injection processes. This paper provides the key results on the computational fluid dynamics (CFD) simulation of WAG injection in a fractured system. We evaluate the impacts of hysteresis, fracture characteristics (aperture, orientation, and fracture density in the network), and the three-phase relative permeability of available phases during the WAG injection. The CFD model simulates an immiscible WAG injection, and the CFD results are compared to the experimental data in a strongly water-wet sand-pack. Similar to the experiments, we simulate Maroon crude as the oil phase, and synthetic brine, and pure CO2 at 100 °C and atmospheric outlet pressure. The CFD results are in excellent agreement with the experimental data. The absolute relative error is less than 12% for predicting the ultimate oil recovery factors (RFs) in water flooding (WF) and gas injection (GI) cycles. Including the three-phase hysteresis significantly increases the accuracy of the WAG process simulation, while excluding hysteresis underestimates the instantaneous RFs at each cycle (especially GI cycles) and the ultimate RF by 4%. We also analyze the fracture pattern and configuration; adding fractures to the system increases the system effective permeability, leading to more contact between the injecting fluid and trapped oil, and consequently higher oil recovery. Connecting a vertical fracture to the horizontal fracture enhances the recovery through strong connections between the vertical and horizontal blocks. An increase in the fracture aperture from 0.5 to 3 mm increases the RF from 50% to 59%. The fracture inclination angle from 30° to 90° increases the ultimate RF by only 2%. Including gravity forces in vertical model orientation results in overall improvement in RF through engaging both matrix and fracture media in all cycles. As the permeability contrast between the matrix and fracture media decreases, the flow communication between the two regions increases, which improves the recovery performance of the WAG process. Our simulation results can help to further understand the effect of various parameters and operational conditions on WAG injection performance in fractured reservoirs.

Investigations of Miscible Water Alternating Gas Injection Efficiency in Layered Sandstone Porous Media

Carbon dioxide (CO2) flooding deliberated as one of the most common and feasible used gas to improve oil recovery. CO2 utilisation has grown significantly due to availability, greenhouse effect and easy achievement of miscibility relative to other gases. There have been limited experimental efforts conducted at core-scale focused on evaluating the influence of permeability heterogeneity on oil recovery. Thus the results from this manuscript are essential to highlight the importance of geological uncertainties in the current and future enhanced oil recovery projects. This manuscript presents a coupled experimental and simulation study to assess the effect of cross bedded reservoir heterogeneity on WAG flooding performance. We performed core flooding experiments with a fluid system consisting of n C10, synthetic brine, and CO2 at a temperature of 343 K and 17.2 MPa pore pressure. In addition to the experimental work, a 2D core scale CMG-GEM simulation associated with PVT module CMG WinProp has been built based on our experimental results. We found that oil recovery decreases dramatically with increasing permeability ratio of cross bedded core samples. Besides, our results revealed channelling of injected CO2 in high permeability beds leaving a considerable amount of oil untouched in low permeability bed. Furthermore, we pronounced a water shielding effect which reduces further contact of the injected CO2 with oil. We thus conclude that reservoir heterogeneity significantly impact WAG flooding performance and evaluation of these influences on oil recovery before any field application are essential.

Study on the optimization of injection modes and injection parameters for natural gas in ultra-low permeability reservoir

The heavy gas breakthrough is a serious problem when developing the ultra-low permeability reservoir by natural gas, one available way to deal with this difficulty is to adjust the injection mode, such as the water alternating gas (WAG) injection and the intermittent gas (IG) injection. In order to slow down the gas breakthrough and to enhance oil displacement efficiency in ultra-low permeability reservoir better, the injection modes are compared and the injection parameters are optimized. Based on the ultra-low permeability core experiments, the WAG flooding and the IG flooding after gas fingering are simulated. The displacement efficiencies and the injection differential pressures of these two injection modes are compared. And the suitable injection mode in ultra-low permeability reservoir is confirmed. Furthermore, the experiments with the selected injection mode for several flooding rounds and different flooding periods are made, and the optimized injection parameters are achieved. The results show that both the WAG injection and the IG injection can slow down the gas breakthrough and improve the oil displacement efficiency. The oil displacement efficiency improvement of WAG injection and the IG injection is close, but the pressure of WAG injection is much higher than the one of IG injection. The IG injection can be confirmed as the optimized injection mode in the ultra-low permeability reservoir after gas fingering as the pressure requirement. The economic IG flooding round is 7 at most as the oil displacement efficiency stops improving till the flooding round increases to 7. The optimized IG flooding period after gas breakthrough in ultra-low permeability reservoir is 6 h under the differential pressure of 2MPa limited by the dissolving ability of natural gas.